Gas purification can generally be divided into three main categories:                Dehydration;        Hydrocarbon dew point control; and        Acid gas removal.        
Conventional technologies used for these processes can generally be divided into the following categories:                Absorption of a gas component into a chemical;        Adsorption of a gas component on a solid surface;        Membrane permeation by selective barriers to gas components;        Condensing the gas stream in order to remove a liquefied phase; and        Chemical conversion of a gas component into a new liquid or solid component which is easier to separate from the gas.        
Which technology to use in a given application depends on the type of gas component to be separated from the bulk phase, the concentration of the component, and requirements of the composition of the product gas. For the removal of sour components, e.g., CO2 and H2S, from natural gas, the most common method is using solvents such as alkanolamines. The absorption takes place in absorber columns and the alkanolamines are recovered in stripper columns by increasing the temperature and flashing off the CO2.
Amine absorption separation has been in commercial use for many decades and provides a product gas that meets requirements as to remaining CO2 content, heating value, etc., but which requires a substantial amount of equipment with the energy consumption related to the recovery of the solvents being high. The contactor columns can have diameters of up to about 5 meters and total heights of up to about 30 meters. The dimensions of the strippers are in the same range. Emissions of toxic components are also an issue related to this gas purification technology.
Another technology being used in the recent years is separation of gas by using membranes. The membranes typically consist of a porous matrix with a coated layer that consists of a polymer that is selective as to which gas molecules can pass through and which are retained. Such membranes have proven to be quite successful since they are not dependent on using solvents in the purification process.
The above mentioned processes for natural gas purification (removal of sour gas components) are normally applied at onshore gas processing facilities or at topsides facilities when gas processing is applied in an offshore environment.
US 2002/0195251 A1 describes a subsea system for treatment of natural gas where the gas flow from a natural gas well is pumped up, led through a heat exchanger and to a gas/liquid separator, from which the gas phase is cooled before it is led to a membrane separator, which can include one or more membrane separators. The purified gas is transported on from the separation unit, while the separated impurities are pumped down into a water-containing rock formation. This system does not, however, describe a compression unit and a cooling unit following the membrane separation unit, in order to cool the permeate flow before it is injected into the well.
Maurand, N et al., “Coupling compositional flow, thermal effects and geochemistry reactions when injecting CO2 in a carbonated oil field”, 7th Trondheim CCS Conference, TCCS-7, Jun. 5-6, 2013, Trondheim, Norway, Energy Procedia 51 (2014) 316-325, describes computer modeling performed to investigate the thermal effect and geochemical reactions of injecting CO2 into an oilfield. Simulations were performed at four different temperatures of the injected CO2 gas. The results of the simulations show that the cooling of the oil reservoir by injecting CO2 increases the mobility in the reservoir and contributes positively to the recovery of oil from the field.
DE 10 2006 015 088 describes a process for the removal of water and other non-condensable components from natural gas. The process comprises compressing and cooling of the inflowing gas mixture in a first compressor stage, where the resulting condensate from the natural gas stream is removed in a first gas/liquid separator, and the gas is led through a demister and further to a first membrane separation stage. In the separation stage, the impurities are removed over the membrane and this flow is compressed, cooled, condensate is removed in a gas/liquid separator, and is led via a demister to a second membrane separation stage. Retentate from the first and second separation stage is removed for further use, while the collected liquid is discharged.
US 2006/0042463 A1 describes a process and a method for the removal of acid components in a flow of natural gas by using a two-stage membrane separation process. The crude gas is cooled and pretreated before it is brought into contact with a membrane separation unit. Permeate from this unit is cooled then compressed, led through a filter separator, to enter the second membrane separation stage. Permeate from this stage is cooled before being led to a micro turbine generator.
CO2 has been used for decades to flood oil reservoirs since this can improve the recovery of hydrocarbons from the reservoir. All current applications of this technology in an industrial scale are performed on onshore fields. In the recent years, however, this technology was increasingly considered for use in offshore oil fields due to the desire to extract additional oil resources. This method also provides for the simultaneous storage of CO2 in the oil reservoirs and therefore contributes to the abatement of greenhouse gases.
When CO2 or hydrocarbon gases are used to flood oil reservoirs, this is mainly arranged by the intermittent injection of the gas and water in an operation called Water Alternating Gas or “WAG”. Another way to flood such a reservoir is by the simultaneous injection of the fluids. In this case, the operation is called “SWAG”.
A major constraint to applying CO2 flooding in offshore oil reservoirs is, however, the handling of the well stream that results from the flooding. A part of the CO2 gas will follow the production of hydrocarbons and water and lead to rapidly increasing amounts and concentrations of CO2 which will reach the well stream separation equipment on the offshore production facility. These facilities may not have been designed for treating such flow conditions. Very high modification costs may thus be needed to accommodate the facility with new treatment capacity. As noted above, the equipment needed for CO2 separation by conventional methods is generally significant and with little spare weight and space on offshore facilities, the commercial use of offshore CO2 flooding has to date not been sanctioned in commercial projects.
Moreover, when CO2 or hydrocarbon gases are mixed with or contact water, as in WAG or SWAG operations, great attention must be paid to the mixing or contacting conditions to avoid the formation of hydrates. This typically occurs in the temperature range of 15-20° C., depending on the pressure. These temperatures may be reached when transporting CO2 in underwater pipelines unless these are insulated or heated. When such a risk for hydrate formation exists, valves are usually arranged to avoid the two fluids coming into contact with each other through leaking valves. Antifreeze chemicals such as MEG or methanol are used as a buffer between water and hydrocarbon gas/CO2 in an over-pressurized barrier so that a potential leakage is routed from the MEG/methanol to the water/gas side.